The present disclosure generally relates to subterranean treatment operations, and, more specifically, to methods for enhancing a resin coating formed in conjunction with a subterranean treatment operation.
Treatment fluids can be used in a variety of subterranean treatment operations. Such treatment operations can include, without limitation, drilling operations, stimulation operations, production operations, remediation operations, sand control operations, and the like. As used herein, the terms “treat,” “treatment,” “treating,” and grammatical equivalents thereof will refer to any subterranean operation that uses a fluid in conjunction with achieving a desired function and/or for a desired purpose. Use of these terms does not imply any particular action by the treatment fluid or a component thereof, unless otherwise specified herein. More specific examples of illustrative treatment operations can include drilling operations, fracturing operations, gravel packing operations, acidizing operations, scale dissolution and removal operations, sand control operations, consolidation operations, and the like. Such treatment operations are conducted in a wellbore penetrating a subterranean formation. As used herein, the term “wellbore” will refer to a borehole drilled in a subterranean formation.
A downhole coating can be formed in conjunction with a number of treatment operations. Illustrative treatment operations in which downhole coatings are formed in a wellbore include, for example, consolidation operations, fines control operations, sand control operations, proppant or gravel pack stabilization operations, and the like. Depending on the intended nature of the treatment operation, a downhole coating can be configured for either temporary or permanent deployment in the wellbore. As used herein, the term “in the wellbore” will refer to any one or more of the following: the borehole defining the wellbore, the subterranean formation surrounding the wellbore, or a portion of the subterranean formation adjacent to propped fractures.
Substantially non-degradable resins are frequently used for deploying a downhole coating in a permanent configuration within a wellbore. However, even resin coatings configured for permanent deployment gradually degrade upon exposure to the harsh conditions present in the downhole environment. For example, continuous exposure of the resin coating to water vapor and high downhole temperatures and pressures can lead to crack formation and propagation. The cracks can lead to eventual failure of the resin coating. Failure of a resin coating can negatively impact a well's lifetime and production capacity. Expensive and time-consuming workover and remedial operations may be needed to address the failure of a resin coating.
Without being bound by any theory or mechanism, it is believed that the failure of resin coatings often occurs in the downhole environment due to the low mechanical strength and poor thermal conductivity of many unmodified resins. Although the mechanical strength of resins can often be improved with reinforcing materials, such as reinforcing fibers (e.g., fiberglass), most of these reinforcing materials do not enhance thermal conductivity values to any significant degree. Similarly, many thermal conductivity enhancers do little to improve the mechanical strength of resins. Of most significance, many conventional materials for enhancing mechanical strength or thermal conductivity can be difficult to effectively introduce into a downhole environment. For example, reinforcing fibers or thermal conductivity enhancers can often be problematic to pump and can negatively impact the properties of a treatment fluid used to introduce the resin into a wellbore. High loadings of reinforcing materials or thermal conductivity enhancers may be particularly problematic in this regard. High resin contents can upset the fine balance between conveying mechanical strength to a proppant pack while maintaining its conductivity.